Hydrocarbons normally accumulate only in geological formations with certain structural and porosity characteristics that create hydrocarbon reservoirs. For example, a convex porous geological layer underlying a nonporous layer, as in FIG. 1, is an effective structural trap. More common are stratigraphic traps as in FIG. 2 in which a porous inclined reservoir layer is capped on top and at the updip end with an effective sealing rock.
The study of seismic disturbances in the earth, called seismology, has been used for decades in exploring for structural and stratigraphic traps. Exploration by seismology begins by artificially inducing a seismic surface disturbance using explosives, air guns or mechanical vibrators. The resulting seismic waves propagate into the earth and are partially reflected back toward the surface by the interfaces between geological layers. The reflected waves are then sensed and recorded by detectors on the surface at some measured distance from the seismic wave source. The portion of the wave that is reflected is determined by the reflection coefficient of each geological interface, which varies with the variance in the lithological characteristics between the upper and lower layers adjacent to the interface. See generally M.B. Dobrin, Introduction to Geophysical Prospecting (1976), the contents of which are incorporated herein by reference.
The seismic waves reflected from various points in a vertical plane through the earth can be displayed side by side as traces on paper to obtain a "seismic section." Early seismologists directly recorded these traces in the field as side by side irregular lines, the length of which was proportional to the depth of the reflecting interfaces. Modern techniques record the reflected waves digitally on magnetic tape or in computer memories. The digitally recorded waves are later statically and dynamically corrected, usually by automated means, and are then displayed side by side for interpretation by a seismologist.
The use of seismology in exploration for hydrocarbons can be divided into the three areas described below: seismic stratigraphy, direct hydrocarbon indicators ("flat spots" and "bright spots") and seismic lithology.
Seismic Stratigraphy. Hydrocarbon reservoirs are commonly found in stratigraphic traps of porous sand or sandstone. It is well known in the art that a deposition of sand is more probable in some environments than in others. For example, beach environments are likely to receive sand depositions. It has been found that some of the environments conducive to sand deposition where hydrocarbon reservoirs may later accumulate are associated with characteristic stratigraphic shapes. Because these sands usually have lithological parameters different from those of adjacent geological layers, the interface between the sand and the adjacent layers will reflect seismic waves. The art of recognizing the characteristic shapes of these sand environments on seismic sections is called "seismic stratigraphy."
A limitation on the value of seismic stratigraphy is that it tells nothing of the actual composition of the geological layers; it simply tells the shape of the layers. Therefore, the interpreter rarely can determine whether a hydrocarbon reservoir actually exists. At the most, he can only recognize geological shapes that experience suggests are more likely than other shapes to be of a composition and structure conducive to hydrocarbon reservoir accumulation.
Direct Hydrocarbon Indicators. Under certain narrow conditions a natural gas charged reservoir will have a high seismic wave reflection coefficient at the top interface between the gas and the cap layer, which will be indicated by an anomalously high reflected wave amplitude. This is often referred to as a "bright spot" on a seismic section. In addition, because the lithological parameters of a gas-charged sandstone reservoir are different from those of a similar water-wet sandstone reservoir, the interface between gas and water at the lower extreme of the gas accumulation may produce another seismic wave reflection anomaly. This is called a "flat spot" on a seismic section. Seismologists have attempted to predict the existence of gas reservoirs by recognizing bright spots and flat spots on seismic sections.
A problem with bright spot and flat spot detection is that only a narrow range of conditions will allow their unambiguous recognition. In some circumstances, the lithological characteristics of layers not containing hydrocarbons can result in interfaces producing bright spots and flat spots. Also, the positioning of the interfaces can focus seismic waves to the surface to simulate bright spots and flat spots.
Seismic Lithology. It has been observed that the seismic reflection amplitude of a given interface varies depending upon distance (called the "offset") between the seismic disturbance source and detector. Those practiced in the art have recently attempted to use this observed variation to help determine hydrocarbon accumulations. This practice of deducing hydrocarbon accumulations from observing variations in reflected wave amplitude with variations in source-detector offset is called "seismic lithology."
One of the earliest documented commercial uses of the seismic lithology technique was in the Sacramento Basin of California in the 1960s. It was found in the Sacramento Basin that certain gas-charged sands were associated with seismic reflection amplitudes that increased with source-detector offset. Because of the Sacramento Basin experience, the industry has generally assumed that an increase in seismic reflection amplitude with increasing offset indicates a gas reservoir. This assumption is incorrect, as demonstrated by numerous field tests of various geological layers. A much more reliable indicator of a gas reservoir is a low Poisson's ratio, which indicates high compressibility. The fallacy of prior art methods relating offset to amplitude is demonstrated in the examples in the following paragraphs, which are from actual wells using mathematically generated seismic data.
FIG. 4 shows the offset amplitude variations for the upper and lower interfaces of a consolidated sand layer between two gassy shale layers. Also shown are the velocity (.nu.), density (.rho.) and Poisson's ratio (.sigma.) parameters for each layer. In the first two graphs, the consolidated sand is gas-charged. These two graphs show an increase in the absolute magnitude of the wave reflected from the top and bottom interfaces with increasing offset. This is in accordance with general industry assumptions and the Sacramento Basin experience regarding offset-amplitude variations in gas charged sands. However, as the third and fourth graphs of FIG. 4 demonstrate, the offset-amplitude variations caused by a water-wet consolidated sand layer between two gassy shale layers are virtually indistinguishable from those caused by the gas-charged sand layer between two similar gassy shale layers. Therefore, an explorationist merely looking for increasing amplitude with increasing offset in a consolidated sand between gassy shales would be likely to mistake a water-wet sand for a gas-charged sand.
Note that there is a distinct difference in the lithological parameters between the water-wet sand and the gas-charged sand of FIG. 4. In particular, Poisson's ratio is much lower in the gas-charged sand than in the water-wet sand. An explorationist equipped with knowledge of those lithological parameters could correctly determine the composition of the tested layers.
The example described in FIG. 5 demonstrate that the offset-amplitude variations of a gas sand layer between two shale layers depends on the consolidation of the gas sand layer. The first two graphs of FIG. 5 show, in the case of a partially consolidated sand, a decrease in the absolute magnitude of the wave reflected from the top and bottom interfaces with increasing offset. However, the third and fourth graphs in FIG. 5 show the opposite result in the case of an unconsolidated sand, also gas charged. Thus, the explorationist looking for amplitude increasing with offset could be led away from the valuable partially consolidated gas-charged sand shown in the first two graphs. An explorationist with knowledge of the lithological parameters of the layers would not make this mistake; both the consolidated and unconsolidated gas sands have low Poisson's ratios indicating high compressibility.
FIG. 6 shows dramatic offset-amplitude variations in porous and nonporous water sand layers between two shale layers. These variations could incorrectly be interpreted as hydrocarbon indicators under methods of the prior art. However, knowledge of the lithological parameters would disprove the existence of hydrocarbons; both the porous and non-porous layers have Poisson's ratios that are too high for a gas reservoir.
FIG. 7 shows offset-amplitude variations that are exactly the opposite of the variations that would be expected under the prior art. The first two graphs of FIG. 7 show only slight offset-amplitude variations for a gas sand between two shales, which would lead explorationists using prior art methods to incorrectly conclude that no hydrocarbons were present. In the third and fourth graphs of FIG. 7, a water-wet sand between two shales shows dramatic offset-amplitude variations, which would lead an explorationist using prior art methods to conclude incorrectly that hydrocarbons were present. Again, both mistakes could be avoided with knowledge of Poisson's ratio for the layers. The gas sand shows a low Poisson's ratio indicating high compressibility, while the water-wet sand shows a high Poisson's ratio indicating low compressibility.
A few practitioners have recognized that, contrary to industry assumptions, the amplitudes of seismic waves reflected from hydrocarbon reservoir interfaces do not necessarily increase with increasing offset. However, the techniques of those practitioners are largely empirical and they have not achieved the breakthrough quantitative process of this invention. For example, in U.S. Pat. No. 4,316,268, Ostrander for Method for Interpretation of Seismic Records to Yield Indication of Gaseous Hydrocarbons, it is stated that the reflected wave amplitude increases with increasing offset in the case of shale overlying gas sands, and decreases with increasing offset in the case of shale overlying gas limestone. Such an approach, of course, requires knowledge of the properties of the overlying layer, which is usually no more available than knowledge of the properties of the underlying layer. Moreover, it is not applicable to the large majority of circumstances in which the offset-amplitude variation does not fit the offset-amplitude variation of shale overlying gas sands, shale overlying gas limestone or some other known layer series. Finally, it usually does not apply to oil exploration, but only to gas exploration in which offset-amplitude variations are likely to be dramatic.
Rather than simply comparing observed offset-amplitude variations of unknown layer series with the offset-amplitude variations of known layer series, the industry has long struggled to develop a quantified method that would use the offset-amplitude variation to determine the distinctive lithological parameters of the geological layers. A principal obstacle to such a quantified approach has been that the theoretical relationships defining offset and amplitude as a function of the lithological parameters are extraordinarily complex. An added complexity arises because the mathematical equations on the subject express the reflection coefficient as a function of the angle of incidence of a seismic wave on a reflecting interface within the ground. This angle of incidence changes instantaneously at each layer interface in accordance with Snells Law, which states p=sin.theta.i/vi, in which p is a constant for a given wave called the ray parameter, .theta.i is the angle of incidence of the wave and vi is the velocity of the wave. Because the wave velocity varies in each layer, the angle of incidence also varies.
Some practitioners attempt to relate the angle of incidence to the measured source-detector offset by assuming that the angle of incidence can be expressed as a simple trigonometric function of the offset and the depth of the interface. However, this is extremely rough and often misleading because the seismic wave path typically assumes a zigzag pattern rather than a line or some other path easily expressable as a function of depth and offset.
A more sophisticated approach used by some practitioners for determining the angle of incidence is through "forward modeling," which is a trial and error technique for fitting the observed amplitude variations with estimated angles of incidence through each interface down to the interface in question. The limitations of this technique are obvious, given that there may be dozens of interfaces between the surface and the interface in question and that the angle of incidence is only one of several independent variables affecting the amplitude variations.
This invention avoids the necessity of estimating the angles of incidence. Instead, it provides a practical and fully automated means to use seismic data for determining with surprising accuracy the subsurface lithological parameters of Poisson's ratio, seismic wave velocity and material density. From these parameters, the actual composition of the geological parameters can be accurately predicted.